Hydrogen Energy And Fuel Cell Technologies: Hydrogen is a flexible energy carrier with potential applications across all energy sectors. It is one of only a few potential near-zero emission energy carriers, alongside electricity and advanced biofuels.
Nonetheless, it is important to note that hydrogen is an energy carrier and not an energy source: although hydrogen as a molecular component is abundant in nature, energy needs to be used to generate pure hydrogen. The hydrogen can then be used as a fuel for end-use conversion processes, for example using fuel cells to produce power.
As is the case for electricity generation, hydrogen production incurs a cost and suffers from thermodynamic losses. Hydrogen can be produced from various primary or secondary energy sources, depending on regional availability.
Primary energy sources useful for hydrogen production comprise renewable sources, such as biomass, and also fossil fuels, such as natural gas and coal. Electricity can also be used for hydrogen generation using electrolysers, which are a pivotal technology for enabling the splitting of water into its components hydrogen and oxygen.
Hydrogen itself contains no carbon – if used in a fuel cell or burned in a heat engine, water or water vapour is the only exhaust. Nevertheless, hydrogen can have a very significant carbon footprint.
Its life cycle carbon emissions are determined by the primary energy source and the process used for hydrogen production, and need to be taken into account when quantifying climate benefits. While not ignoring the implications of hydrogen generation pathways, this roadmap focuses primarily on the demand side of the energy system.
There, hydrogen could play an important role in future road transport, as FCEVs can be a low-carbon alternative to conventional passenger cars and trucks. In buildings, micro co-generation units could increase energy efficiency.
In the longer run, industrial processes in the refining, steel and chemical industries could be substantially decarbonised through the use of hydrogen with a low-carbon footprint. In many, but not all of these applications, fuel cells are an important technology for converting hydrogen to power and heat.
Fuel cells are intimately but not exclusively linked to hydrogen. They can also be used with other fuels such as natural gas or even liquid hydrocarbons, thus helping their early adoption.
Producing hydrogen from electricity and storing it in gaseous or liquefied form could be an option for increasing the flexibility of the energy system, allowing for the integration of high shares of VRE.
Hydrogen can enable “power-to-x” trajectories – its capability of being converted to various forms of final energy, such as power, heat and transport fuels, can be used to join subsystems of the energy system that historically had no, limited or only one-way linkages. This is what makes this roadmap especially challenging.
Many of the technology components are less mature than technologies featured in other IEA Technology Roadmaps, adding greater uncertainty to technological and economic parameters. A proper inter-sectoral view of the energy system also requires integrated modelling, which becomes highly complex if the target is significant temporal and spatial detail.
For this roadmap the IEA ETP toolbox has been enhanced to account for some of the synergies that emerge when high shares of VRE integration on the energy supply side are combined with demand for hydrogen as a fuel.
Rationale for hydrogen and fuel cell technologies
As outlined in the 2015 edition of ETP, contributions to reducing GHG emissions from the energy supply sector and all energy demand sectors will be needed if dangerous climate change is to be prevented.
On the energy supply side, the power sector needs to be deeply decarbonised if an ambitious emission reduction scenario to limit global warming to 2°C above pre-industrial levels is to be achieved.
On a global scale, annual emissions need to be reduced by 85% by 2050 compared to today’s levels, which is achieved in the 2DS to a large extent by an increase of renewable power to about 63% of generated electricity by 2050.
This high level of renewable energy integration, which following the 2DS will need to be exceeded in certain regions such as the European Union, necessitates a deep structural change in the way we operate power systems.
Discussion of low-carbon energy systems frequently centres on issues such as flexibility and system integration. Today’s perception of flexibility is mostly related to energy supply. In fact, it is closely linked to energy storage. Fossil resources store immense amounts of energy.
They can be used when and where necessary, their high energy density (either in gaseous, liquid or solid form) allowing them to be efficiently transported over long distances. This inherently provides the energy system with a lot of flexibility.
In a low-carbon energy system based on high shares of VRE, this temporal and spatial flexibility to modulate energy supply according to demand is limited.
Electricity from VRE carries the temporal and spatial imprint of its resource: sunlight, wind, tidal and wave patterns. Their patterns are not necessarily aligned with variations in demand – with regard both to location and time of supply. This causes periods of supply surplus and deficit, which will differ from one place to another.
Moreover, fluctuating output as a result of weather variability can lead to rapid swings in supply. This is a challenge, because the electricity grid requires electricity supply and demand to be in balance instantaneously and at all times. A suite of options is available to overcome the space and time mismatch of variable electricity supply and demand.
Grid infrastructure, flexible generation, demand-side response and energy storage can all be used in this way, but should be used according to their relative economic performance.
Hydrogen generated from electricity and water can be stored in large quantities over long periods and re-transformed to electricity (power-to-power) – although at an efficiency cost of more than 70% of the input electricity.
It can be mixed into the natural gas grid or converted to synthetic methane power-to-gas) or sold as fuel for FCEVs to the transport sector (power-to-fuel). Hydrogen may thus open up entirely new ways to integrate renewable electricity in the energy system and compensate in part for the loss of flexibility resulting from reduced use of fossil fuels.
Decoupling energy use and carbon emissions on the energy supply side needs to be complemented by measures within energy demand sectors, notably transport, buildings and industry.
The main mitigation options are technological improvement (either through efficiency improvements of conventional technologies or the deployment of new technologies) and behavioural change to reduce energy use, as well as switching to low-carbon fuels.
Road transport is a large carbon emitter, accounting for about three-quarters of all transport emissions. Apart from avoiding road transport demand and shifting it to more efficient transport modes, such as passenger and freight rail, substantially decarbonising the road transport sector can be achieved by:
1) increasing the share of direct use of low-carbon electricity via battery electric vehicles (BEVs) and plug-in hybrid electric vehicles (PHEVs);
2) significantly raising the share of sustainable low-carbon biofuels in combination with high-efficiency hybridised internal combustion engine (ICE) vehicles and PHEVs;
3) the use of FCEVs fuelled by low-carbon footprint hydrogen. All three options can substantially contribute to reducing emissions, but hinge on overcoming different barriers. Energy storage is again pivotal – the higher the demand for autonomy, the greater the need for energy to be stored on board.
BEVs can draw upon existing electricity generation and T&D infrastructure, and rely on the fact that their carbon impact would be reduced by the decarbonisation already taking place in the power sector. Still, batteries face a serious trade-off between energy capacity and weight, and range anxiety and recharging time are major concerns for consumers.
In the case of biofuels, production raises doubts with respect to sustainability and displacement of food production, particularly as considerable amounts of biofuels will be necessary to decarbonise long-haul road freight, aviation and shipping.
By contrast, FCEVs could provide transport utility comparable to today’s vehicles while, at the same time, meeting climate and energy security targets. Here, the challenge is to build up an entirely new hydrogen generation, T&D and retail network.
The main barrier to overcome is the risk related to committing investment in large-scale FCEV production on the one hand, and hydrogen infrastructure roll-out on the other, particularly against a background of high uncertainty with respect to FCEV market uptake.
Therefore, a better understanding of consumer preferences with regard to vehicle range, refuelling and recharging infrastructure provision as well as safety concerns is key to improve projections of the market potential of low or zero-emission vehicles.
Substituting fossil-derived hydrogen with low-carbon footprint hydrogen in industrial applications also offers significant potential for carbon emission mitigation. Globally, the refining, chemical and industrial gas industries use approximately 7.2 exajoules (EJ) of hydrogen per year.
Around 48% of this is currently produced from natural gas, using steam methane reforming (SMR) without CCS, 30% arises as a fraction of petroleum during the refining process, 18% is produced from coal, and the balance (4%) is electrolytic hydrogen.
Altogether, the used hydrogen resulted in annual emissions of approximately 500 megatonnes (Mt) CO2. In general, depending on region-specific natural gas prices, hydrogen produced via large-scale SMR processes is typically available at relatively low costs.
This together with anticipated T&D costs will set the benchmark against which alternative, low-carbon hydrogen production pathways need to be measured. In the steel industry, more efficiently integrating the hydrogen generated in classic blast furnaces in the steelmaking process could deliver significant carbon emission reductions today.
Processes to directly reduce iron ore (DRI) in the presence of hydrogen could unlock an important mitigation potential, especially if low-carbon footprint hydrogen was available at competitive cost. A schematic representation of today’s energy system and a potential low-carbon energy system of the future are shown in Figure 1.
The key difference lies in the different energy vectors used to supply transport, buildings and industry, and in particular the T&D of electricity, heat, and liquid as well as gaseous fuels via different energy networks. Today’s energy system is heavily dependent on fossil fuels and, apart from co-generation, few connections exist between the different T&D systems.
In a future system, hydrogen could play a pivotal role by connecting different layers of infrastructure in a low-carbon energy system. The use of hydrogen as an energy carrier is closely linked to the deployment of fuel cells and electrolysers.
Fuel cells are the key technology to efficiently convert hydrogen into electricity to propel FCEVs, or for using it in other end-use applications in buildings or industry (eventually exploiting the waste heat for heating purposes).
In addition, fuel cells can also convert a range of other hydrocarbon fuels, such as natural gas or methanol, and the immediate use of such fuels for which there is existing infrastructure in fuel cells could be an important step to help reduce technology costs that remain high today.
Electrolyser technology is pivotal to establish the new links between the power sector and transport, buildings and industry. They allow the conversion of renewable electricity into hydrogen, a zero carbon chemical fuel and feedstock, by splitting water into hydrogen and oxygen.
Purpose, process and structure of the roadmap
The purpose of this roadmap is to lay out hydrogen’s potential in different energy sectors, and also its limitations. The roadmap aims to:
- Provide an extensive discussion of the nature, function and cost of key hydrogen technologies.
- Identify applications where using hydrogen can offer the maximum added value.
- Identify the most important actions required in the short and long term to successfully develop and deploy hydrogen technologies in support of global energy and climate goals.
- Increase understanding among a range of stakeholders of the potential offered by hydrogen technologies, particularly the synergies they offer existing energy systems.
This roadmap was developed with the support of a wide range of stakeholders, including members of industry, academia and government institutions.
To facilitate collaboration, the IEA Hydrogen Technology Roadmap team hosted three regional expert workshops to examine region-specific opportunities for and barriers to hydrogen technology deployment (Table 1).
Due to the roadmap’s broad scope, covering both energy supply and several energy demand sectors, the detailed results provided in the “Vision” section focus on selected regions, including EU 4 (France, Germany, Italy and the United Kingdom), Japan and the United States.
The following applications are the focus of this roadmap:
- hydrogen-based systems in energy demand sectors – FCEVs in transport, fuel cell micro co-generation in the residential sector and selected applications in the refining, steel and chemical industries
- hydrogen in the energy supply sector – VRE integration and energy storage, comprising power-to-power, power-to-gas and power-to-fuel
- hydrogen infrastructure – T&D, storage and retail technologieszz key hydrogen generation and conversion technologies – electrolysers and fuel cells
Technology status today
In 2013, global hydrogen usage amounted to a total of 7.2 EJ. To date this hydrogen has not been used as an energy carrier, i.e. it is not converted into electricity, mechanical energy or heat to be used for energy service.
Hydrogen is almost entirely used as feedstock within the refining and chemical industries to convert raw materials into chemical or refinery products.
The generation of hydrogen from fossil resources, its transmission, distribution and use within industry and the refining sector are based on mature technologies and applied on a large scale, and are not the main focus of this roadmap. However, these mature technologies will play an important role in a transition to low-carbon hydrogen.
The use of hydrogen as an energy carrier is beginning to emerge – although the first FCEVs were developed in the 1960s, it is only in the last ten years that the technology has developed to an extent that certain car manufacturers are announcing the launch of FCEVs.
Toyota launched its Mirai (“Future”) model in Japan in 2014, Hyundai is planning to begin the sale of FCEVs in the near future (the Hyundai Tucson FCEV has been available for lease since summer 2014), and Honda announced plans to launch its next generation FCEV in 2016.
Although predicted production numbers are a small fraction of conventional passenger car sales, or even those of electric vehicles, they show the increased interest of car manufactures in this technology.
A similar trend can be observed in the field of energy storage applications. Increasing numbers of hydrogen-based large-scale energy storage demonstration projects are being launched, planned or announced, with a remarkable concentration of activity in Germany, motivated by the attempt to explore benefits for the integration of VREs.
Likewise, opportunities to store large amounts of hydrogen using chemical hydrides are being actively explored in Japan. Japan certainly leads the field in the stationary application of fuel cell technology, with more than 120 000 “Ene-farm” domestic fuel cell micro co-generation systems already installed.
In the following sections, technology status and opportunities are reviewed for hydrogen and fuel cell applications and individual technologies. FCEVs together with hydrogen T&D and retail infrastructure, hydrogen-based energy storage systems, hydrogen technologies in industry and fuel cells in buildings are considered in turn.
This is followed by a more detailed discussion of some of the key technologies for generating, using and storing hydrogen.
Hydrogen in transport
An overview of hydrogen systems in the transport sector and their techno-economic parameters is shown in Table 2.
More detailed technical data on hydrogen technology components, such as fuel cells and electrolysers, are briefly discussed in the sections “Key hydrogen production technologies” and “Key hydrogen conversion technologies” as well as in the Roadmap Technology Annex.
Although other pathways to use hydrogen as a fuel in transport are feasible, e.g. via the use of synthetic methane in compressed natural gas (CNG) vehicles or through conversion to methanol, the current analysis focuses on FCEVs and the use of pure hydrogen.
FCEVs are essentially electric vehicles using hydrogen stored in a pressurised tank and a fuel cell for on-board power generation. FCEVs are also hybrid cars, as braking energy is recuperated and stored in a battery.
The electric power from the battery is used to reduce peak demand from the fuel cell during acceleration and to optimize its operational efficiency. Being both electric and hybrid vehicles, FCEVs benefit from technological advancement in both technologies, since they have a significant amount of parts such as batteries and power electronics in common
Today around 550 FCEVs (passenger cars and buses) are running in several demonstration projects across the world (Table 3). A small number of fuel cell heavy freight trucks (HFTs) are currently being used in a demonstration project at the port of Los Angeles, testing the usability of range extenders with electric trucks.
To date, FCEVs are fuelled with gaseous hydrogen at pressures of 35 MPa to 70 Mpa. As 70 MPa tanks allow for much higher ranges at acceptable tank volumes, most recent demonstration vehicles are equipped with these.
Currently, on-road fuel economy is around 1 kg of hydrogen per 100 km travelled, and demonstration cars have ranges of around 500 km to 650 km.
Since the driving performance of FCEVs is comparable to conventional cars and refuelling time is about the same, FCEVs can provide the mobility service of conventional cars at much lower carbon emissions, depending on the hydrogen generation pathway (Figure 2).
Vehicle costs remain high – FCEV prices announced to date have been set at around USD 60 000 (Toyota, 2015) during the early market introduction phase. Announced prices might rather reflect the assumed customers’ willingness to pay than the costs to produce the vehicles.
Current FCEV models are targeted at high-income and technophile early movers living close to hydrogen refuelling infrastructure clusters, which are starting to develop in California, Germany, Japan and Korea.
The high cost of the fuel cell systems is driving total vehicle costs, and the current challenge lies in reducing fuel cell stack and balance of plant (BOP) costs while simultaneously increasing lifetime.
While economies of scale have huge potential to drive down fuel cell costs, the cost of the high-pressure tank is largely determined by expensive composite materials, which are expected to fall much more slowly (Argonne National Laboratory – Nuclear Division, 2010).
This is why the focus of recent R&D has been on accelerating cost reductions in composite materials for high-pressure tanks. To bring down the costs of the entire FCEV, manufacturers are currently focusing on “technology packaging”, to finally be able to mount the fuel cell power train on the same chassis used for conventional cars.
To realise their full performance potential against conventional cars, FCEVs target the medium and upper size car segments.
Initially, costly technologies are typically introduced in premium cars, but in the longer term more than three-quarters (vehicle class C and higher [IEA (2012)]) of the passenger light-duty vehicle (PLDV) market would be suitable for fuel cell technology.
Since FCEVs will target the same vehicle class like plug-in hybrids – medium and upper size class vehicles able to cover large distances – these might be the closest competing low-carbon technology. Compared to plug-in hybrids, FCEVs could enable very low-emission individual motorised transport.
At high annual production rates and under optimistic assumptions with regard to fuel cell systems and hydrogen storage tanks, FCEVs have the potential to be less costly than plug-in hybrids. This is largely due to their lower complexity since they do not require two different drive-trains.
Fleet vehicles can play a significant role in the initial market introduction phase. Refuelling at a base location allows the necessary hydrogen refuelling infrastructure, and the associated costs, to be kept to a minimum.
As a result of better utilisation of the refuelling equipment and higher annual mileages, economic viability of fleet FCEVs could be achieved earlier than for individually owned vehicles. The French HyWAY programme, for example, aims to de-risk the development of infrastructure for FCEVs by focusing on captive fleets.
Broad personal vehicle ownership of FCEVs may also hinge upon overcoming consumer concerns about passenger safety in collisions, ability of the general public to safely refuel, and safety in tunnels or enclosed parking spaces.
Heavy-duty vehicles such as trucks and buses can also be equipped with fuel-cell powertrains. Significant experience with fuel cell buses already exists and partly results from being able to draw upon the fleet vehicle advantage. Public transport subsidies are common and could ease the introduction of fuel cell technology in that field.
Furthermore, co-benefits such as reduced air pollution can be an important argument for FCEV and particularly fuel-cell bus deployment, especially in heavily polluted and densely populated urban areas around the world.
Fuel cell trucks are one of only very limited options available to deeply decarbonise heavy-duty, long-haul road freight transport. Although competition with other low-carbon technologies is less pronounced in that segment, fuel cell long-haul HFTs will face difficulty competing with advanced conventional trucks.
HFT diesel engines can already achieve high efficiencies (up to 40%) during constant highway cruising speeds. Fuel cell efficiencies decline with increasing power output, and using them in HFTs decreases the efficiency benefit compared to conventional technology.
Furthermore, as HFTs require long-range autonomy, on-board storage of the necessary volumes of hydrogen becomes critical. Compared to conventional diesel technology, hydrogen stored at 70 MPa still needs four times more space to achieve the same range, even taking into account the higher efficiency of the fuel cell powertrain.
The potential role of fuel cell technology in HFTs is thus more uncertain.
Hydrogen refuelling stations can be supplied by one of two alternative technologies: hydrogen can be produced at the refuelling station using smaller-scale electrolysers or natural gas steam methane reformers, or can be transported from a centralised production plant.
Each approach has its own advantages and trade-offs. While large-scale, centralised hydrogen production offers economies of scale to minimise the cost of hydrogen generation, the need to distribute the hydrogen results in higher T&D costs. Meanwhile, the opposite is true for decentralised hydrogen generation.
While T&D costs are minimised, smaller-scale production adds costs at the hydrogen generation stage.
Finding the optimal network configuration requires detailed analysis taking into account the full range of local factors, such as geographic distribution of resources for hydrogen production, existing hydrogen generation and T&D infrastructure, anticipated hydrogen demand at the retail station and distance between the place of hydrogen production and hydrogen demand.
However, economies of scale realised in large centralised hydrogen generation facilities tend to potentially outweigh the additional costs of longer T&D distances. A number of options are available for hydrogen T&D: gaseous truck transport; liquefied truck transport; and pumping gaseous hydrogen through pipelines (Table 4).
A trade-off exists between fixed and variable costs: while gaseous truck delivery has the lowest investment cost, variable costs are high as a result of the lower transport capacity. The opposite is true for pipelines – fixed costs are driven by high investment costs. Once the pipeline is fully utilised, the variable costs are low.
The lowest-cost pathway depends on many factors, with hydrogen demand at the refuelling station and T&D distance being the most important.
Hydrogen refuelling stations
Hydrogen refuelling stations are a critical element in the fuel supply chain for FCEVs, as providing a minimum network density is a prerequisite to attaining consumer interest. They can be exclusively for hydrogen or part of a multi-fuel station.
The set-up of a hydrogen station is largely determined by daily hydrogen demand, the form of hydrogen storage on board the vehicle (e.g. the pressure and the phase), and the way hydrogen is delivered to or produced at the station. Determining the optimal size of a station is a critical step.
While very small stations with daily capacities of 50 kg to 100 kg of hydrogen might be necessary in the beginning (basically allowing for 10 to 20 refills a day), stations up to 2 000 kg per day will be needed in a mature market.
The link to hydrogen T&D technologies is obvious. While small stations could be based on gaseous trucking or on-site hydrogen production, liquefied trucking or the use of pipelines are the only options for hydrogen delivery to stations larger than 500 kg per day, if the hydrogen is not produced on-site.
The set-up of the station hence implies a certain path dependency, which complicates investment decision-making, as multiple risks (mainly linked to the pace of FCEV market uptake and hydrogen demand) need to be taken into account.
Risks associated with investment in hydrogen refuelling stations
The investment risk associated with the development of refuelling stations is mainly due to high capital and operational costs, and the under-utilisation of the facilities during FCEV market development, which can lead to a negative cumulative cash flow over 10 to 15 years (Figure 3).
This long “valley of death” can be minimised by reducing capital and operation costs and maximising asset utilisation. High capital costs are mainly linked to hydrogen compression and storage.
The higher the pressure of hydrogen stored on board FCEVs, the more expensive are the compressors needed at the station – a 35 MPa refuelling station is about one third less costly than a 70 MPa station.
The requirement for compression at the station can be minimised either by delivering the hydrogen at high pressure from the hydrogen generation plant, or by lowering the required pressure on board the FCEV. It would even be possible to provide hydrogen at several pressure levels, where only stations on long-distance corridors would provide the option to refuel at 70 MPa.
Clustering hydrogen stations around main demand centres and connecting corridors during the FCEV roll-out phase can ensure maximising utilisation rates.
Several partnerships and initiatives, such as the California Fuel Cell Partnership (CaFCP) in the United States, H2Mobility in Europe or the Fuel Cell Commercialisation Conference of Japan (FCCJ), have made proposals for the optimal roll-out of hydrogen stations so as to provide maximum coverage at minimal cost.
An overview of existing and planned hydrogen refuelling stations is given in Table 5.
To cover the negative cash flow period, direct public support might be needed for hydrogen stations during the FCEV market introduction phase.
As recently published in a paper by Ogden et al, direct subsidies in the range of USD 400 000 to USD 600 000 per station might be required until cumulative cash flow becomes positive, assuming a fast uptake of the Californian FCEV market.
Carbon footprint of hydrogen used in transport
The carbon footprint for different hydrogen pathways and for gasoline and diesel are shown in Figure 4 for the European Union. Depending on the production and T&D pathway, today’s carbon footprint for hydrogen can be significant.
Decentralised hydrogen production (at the refuelling station) using today’s EU grid electricity mix, and including compression to 88 MPa, results in a carbon footprint which is almost three times higher than that for gasoline or natural gas.
Conversely, when produced from renewable power, biomass or fossil fuels with CCS, the carbon content of hydrogen can be reduced to below 20 gCO2eq per MJ.
Still, in combination with the higher efficiency of FCEVs, the use of hydrogen from natural gas SMR without CCS results in lower per kilometre emissions than the use of gasoline in comparably sized conventional cars (see also Figure 2).
Hydrogen T&D and retailing (“Conditioning and distribution”) have a substantial carbon emission contribution, which is mainly due to the energy-intense compression of the hydrogen gas to 88 MPa, but also due to hydrogen T&D using trucks (with hydrogen either in gaseous or liquefied form) or pipelines.
The values shown in Figure 4 are for the European Union and contain relatively long transmission distances for natural gas of 4 000 km (“Transportation to market”). Since transmission distances might be shorter in the United States, carbon footprint values could be slightly lower, while LNG supply in Japan would lead to higher specific carbon emissions.
Furthermore, the comparison suggests that the liquefaction of hydrogen for T&D purposes leads to around 25% to 30% higher carbon emission compared to gaseous truck or pipeline transport. In the future, the carbon footprint of low-carbon hydrogen could be reduced further if low-carbon electricity was used for compression.
Hydrogen for VRE integration
The integration of large shares of VRE into the energy system will go hand-in-hand with the need to increase the operational flexibility of the power system. This implies the need to store electricity that is not needed at the time or the place of generation, or to transform it in a way that it can be used in another sector of the energy system.
A wide range of options and strategies exist to integrate high shares of variable generation (in the order of 30% to 45% in annual electricity generation) cost-effectively without the use of large-scale seasonal storage.
However, taking into account the full range of local conditions (such as regulatory and market structure, the status of existing and planned grid infrastructure investments) when analysing potential deployment opportunities for energy storage technologies, or attaining even higher VRE shares while also achieving the 2DS, can imply a greater need to apply such storage technologies at large scale.
Electricity storage systems can be classified by size according to their input and output power capacity (megawatts [MW]) and their discharge duration (hours). These three parameters finally determine energy capacity (MWh).
Together with the expected annual number of cycles, round-trip efficiency and self-discharge, the annual full-load hours can be determined. Location within the energy system and response time are other important parameters (see also the Technology Roadmap on Energy Storage.
Hydrogen-based technologies are best suited to large-scale electricity storage applications at the megawatt scale, covering hourly to seasonal storage times (Figure 5).
However, hydrogen-based systems to integrate otherwise-curtailed electricity are not restricted to electricity storage only. As mentioned before, hydrogen-based energy storage systems could be used to integrate surplus VRE electricity across different energy sectors, e.g. as a fuel in transport or as a feedstock in industry.
They can be categorised as follows:
- Power-to-power: electricity is transformed into hydrogen via electrolysis, stored in an underground cavern or a pressurised tank and re-electrified when needed using a fuel cell or a hydrogen gas turbine.
- Power-to-gas: electricity is transformed into hydrogen via electrolysis. It is then blended in the natural gas grid (hydrogen-enriched natural gas – HENG) or transformed to synthetic methane in a subsequent methanation step. For methanation, a low-cost CO2 source is necessary.
- Power-to-fuel: electricity is transformed into hydrogen and then used as a fuel for FCEVs in the transport sector.
- Power-to-feedstock: electricity is transformed into hydrogen and then used as a feedstock, e.g. in the refining industry.
All hydrogen-based VRE integration pathways are based on several transformation steps, which finally lead to rather low efficiencies over the whole conversion chain in the range of 20% to 30% (Figure 6). It is important to only compare final energies of the same quality, for example electricity either used in the power system or on board FCEVs.
The greater the number of conversion steps included, the lower the overall efficiency. The trade-off between power-to-power and power-to-gas options lies within the higher overall efficiency of pure power-to-power applications versus the possibility of using existing storage and T&D infrastructure for power-to-gas systems.
The latter might be a strong argument in the near term – otherwise-curtailed renewable electricity could be integrated into the energy system via blending hydrogen to up to 5% to 10% in the natural gas mix, or transforming it directly to synthetic natural gas via methanation.
Although no compatibility issues with subsequent end-use technologies arise in case of power-to-gas including methanation, the poor overall efficiency is likely to pose a substantial barrier for deployment.
In an electricity system with high levels of VRE, it can be expected that supply will outstrip demand in some periods of the day and year. This has been labelled “excess” or “surplus” electricity.
While some situations might be envisaged in which the storage operator incurs no costs, curtailed VRE electricity is generated at the same costs as VRE electricity required by the system, i.e. the consumer will pay for curtailed electricity through higher per unit electricity prices, since capital costs need to be recovered by selling less output electricity than in the case with no curtailment.
Nevertheless, in this case, conversion efficiency has no impact on levelised costs of the final energy. However, using otherwise-curtailed VRE power to generate hydrogen poses an economic challenge for multiple reasons.
Firstly, electrolysers have significant investment costs, which means that they will only be cost effective if they are operated for a sufficient amount of time during the year. As periods of surplus VRE generation will occur only for a limited amount of time, relying exclusively on generation surpluses is likely to be insufficient to reach sufficient capacity factors.
Hence, it is likely that electricity with at least some value will be used for hydrogen production. Secondly, each conversion step on the way from electricity to hydrogen and back to electricity entails losses (Figure 6). Losses are of minor importance if the input electricity cannot be used for other applications, i.e. it would otherwise need to be curtailed.
However, hydrogen generation will compete with other possible uses of surplus electricity, such as thermal storage. These challenges point to two areas for technology improvement: increasing efficiencies and reducing investment costs.
Only focusing on improving the technology is not sufficient; new and more integrated approaches need to be applied to create viable business cases.
As for all long-term, large-scale energy storage systems, annual full-load hours are limited. While technology components such as electrolysers and fuel cells remain expensive, all possible energy system services or by-products need to be exploited to the fullest extent possible, adopting the benefits stacking principle.
When using electrolysers and fuel cells, a number of by-products, such as oxygen (during electrolysis) or process heat are produced, which need to be sold separately or used on site.
In case of power-to-power systems, it is beneficial not only to sell power generated from low-value, surplus electricity, but also to provide ancillary services and to take part in the power control market. Here, the provision of controllable negative and positive load is remunerated.
Participating in different energy markets can help to create profits.
Bi-generation (hydrogen and electricity) or even tri-generation systems (hydrogen, electricity and heat) offer the possibility of selling their products at the respective highest price, i.e. electricity and heat during times of peak demand and hydrogen to the transport sector, depending on the market conditions.
Large-scale underground hydrogen storage
Storing hydrogen-rich gaseous energy carriers underground has a long history and became popular with the use of town gas to provide energy for heating and lighting purposes in the middle of the nineteenth century.
A geological formation can be suitable for hydrogen storage if tightness is assured, the pollution of the hydrogen gas through bacteria or organic and non-organic compounds is minimal, and the development of the storage and the borehole is possible at acceptable costs.
Actual availability of suitable geological formations where energy storage is required is another limiting factor.
Comparing different underground storage options with respect to safety, technical feasibility, investment cost and operational cost, using salt caverns currently appears to be the most favourable option (Table 7), being already deployed at several sites in the United States and the United Kingdom.
Power-to-gas in Europe: storage potential and limitations
Most developed countries have extensive natural gas T&D networks, including significant natural gas underground storage in depleted oil and gas fields, and salt caverns. This existing infrastructure offers huge energy storage potential if hydrogen produced from otherwise-curtailed renewable electricity was blended into natural gas (HENG).
For example, the EU natural gas grid accounts for more than 2.2 million km of pipelines and about 100 000 million cubic metres of natural gas (which equals roughly 1 100 TWh) can be stored in dedicated storage sites.
Assuming a volumetric blend share of 5% hydrogen in the natural gas, a theoretical storage potential of around 15 TWh of hydrogen (or roughly 9 TWh of output electricity) could be available using the existing natural gas storage infrastructure.
If all natural gas used during a year in Europe was blended at the same share, more than 60 TWh of hydrogen (roughly equalling 36 TWh of output electricity) could be integrated in the energy system. Blending hydrogen into the natural gas grid faces several limitations.
First, the ability of hydrogen to embrittle steel materials used for pipelines and pipeline armatures necessitates upper blending limits of around 20% to 30%, depending on the pipeline pressure and regional specification of steel quality.
Second, the much lower volumetric energy density of hydrogen compared to natural gas significantly reduces both the energy capacity and efficiency of the natural gas T&D system at higher blend shares.
At 20% volumetric blend share, flow rate needs to be increased by around 10% to provide the same energy to the customer, and pipeline storage capacity needed to balance intra-day fluctuations decreases by 20%. By far the strongest restriction is set by compression stations and various end-use applications connected to the gas grid.
According to a recent German study, compressing stations, gas turbines and CNG tanks (e.g. in CNG vehicles) currently restrict acceptable blend shares to 2% by volume without any further adjustment (Figure 7).
A recent article in Hydrogen Energy provides a good overview of the technical and economical parameters of almost 50 power-to-gas pilot plants (of which the majority remain in operation), concluding that apart from the technical core components, design and size as well as control strategy and system integration have a significant influence on overall system efficiency.
Unsurprisingly, efficiency, cost, reliability and lifetime of electrolysers are the main areas where improvement is needed. To date, few of the pilot plants have been operated for lengthy periods. In the near term, the potential of power-to-gas applications to contribute to VRE integration might be constrained to specific locations fulfilling a suite of prerequisites.
It requires the local availability of significant amounts of otherwise-curtailed renewable power and an existing natural gas infrastructure with well-known end-use applications. Blend shares of up to 10% of hydrogen might be viable in local natural gas distribution networks, if modifications to gas turbines located downstream were applied and no CNG cars were supplied.
The summary report of the recent workshop titled ”Putting Science into Standards: Power-to-Hydrogen and HCNG” held at the Joint Research Centre (JRC) of the European Commission in Petten, concludes, amongst others, that setting a clear limit for blending hydrogen into natural gas is currently seen as “premature”.
It underlines the need for harmonisation of current and future standards with regard to the allowed hydrogen content in gas mixtures, and points out at CNG vehicle tanks to be a main bottleneck for HENG application.
Hydrogen in industry
Most of today’s hydrogen demand is generated and used on industrial sites as captive hydrogen. In the EU more than 60% of hydrogen is captive, one-third is supplied from by-product sources, and less than 10% of the market is met by merchant hydrogen.
In general, industrial hydrogen demand offers a significant potential for carbon emission mitigation, but the cost of low-carbon hydrogen is critical.
Hydrogen in the refining industry
Most of the hydrogen used in the refining industry is used for hydro-treating, hydro-cracking and desulphurisation during the refining process. A steadily growing demand for high-quality, low-sulphur fuels, together with a decline in light and sweet crude oils, is leading to a growing demand for hydrogen.
In the past, most of the required hydrogen was produced on site from naphtha, which itself is a refinery product, using catalytic reformation.
Matching the hydrogen balance is becoming increasingly difficult, and therefore the oil refining industry is using more hydrogen from natural gas steam reformation, most often produced in large dedicated plants managed by industrial gas companies.
Under business-as-usual assumptions, it is estimated that by 2030 more than twice the amount of hydrogen will be used in the refining sector compared to 2005.
Most of the growth is expected to take place in North and South America, where the impact of using super-heavy crudes and crude oil from oil sands is most significant. China could see a tripling in hydrogen demand in the refinery sector.
In addition to conventional fuel refining, the upgrading of second-generation, sustainable biofuels produced from lignocellulosic biomass might also demand considerable amounts of hydrogen for hydro-deoxygenation in the future.
The decarbonisation of hydrogen can therefore have a significant impact on reducing the carbon footprint of conventional fuels and biofuels during the refining process. Considerable experience in transmitting hydrogen via pipeline already exists.
In the United States the existing hydrogen pipeline system amounts to some 2 400 km, while in Europe almost 1 600 km are already in place.
Hydrogen in the steel industry
Hydrogen is generated in the steel industry as part of by-product gases during the coke, iron and steelmaking processes. For the most part, these off-gases are used to contribute to on site thermal requirements.
Currently, 71% of steel production is based on the reduction of iron ore in conventional blast furnaces (World Steel Association, 2014) where coke, coal and/or natural gas are used as reducing agents. The resulting pig iron is then reacted with oxygen in a basic oxygen furnace in order to remove excess carbon content from the iron and to generate liquid steel.
Hydrogen-containing gases are generated during coke production (coke oven gas, COG), and also in the blast furnace (blast furnace gas, BFG) and the basic oxygen furnace (basic oxygen furnace gas, BOFG).4 These gas streams globally represent around 8.0 EJ per year and can displace other fossil fuels for heating purposes once collected and treated for reuse on site.
In 2012, around 68% were reused in iron and steel production processes; alternatively these gases are flared. The more efficient use of by-product hydrogen during the steelmaking process can contribute to improved overall energy efficiency and hence reduced carbon emissions.
In order to minimise the need for investment in dedicated hydrogen production plants, by-product hydrogen could also be used as a fuel for FCEVs during the early stages of market introduction. However, purification and cleaning of the hydrogen gas necessary for further use in proton exchange membrane fuel cells (PEMFCs) is economically challenging.
Hydrogen-rich gases can also be used as a reducing agent in alternative methods of steel production. Both, the DRI process and the smelt reduction (SR) process allow the production of iron without the need for coke. As coke production is very carbon intensive, important emission reductions can be achieved when the whole process chain is assessed.
In DRI processes, further emission reductions are feasible with the use of hydrogen with a low-carbon footprint. Instead of using natural gas as reducing agent, hydrogen produced from fossil fuels with CCS or renewable electricity could significantly reduce carbon emissions, if available at competitive costs.
Several research programmes, such as the European-based Ultra-Low-Carbon Dioxide Steelmaking (ULCOS), have focused on improving the performance of DRI and SR processes and exploring alternatives to optimise the use of process gas streams as iron ore reducing agents.
Within these programmes, alternative blast furnace arrangements have been developed that collect, treat and reuse the blast furnace top gas as a 4. These gases typically contain hydrogen in the range of 39% to 65% by volume for COG, 1% to 5% by volume for BFG and 2% to 10% by volume for BOFG reducing agent within the process.
Compared to a typical blast furnace, coke demand per tonne of pig iron has been significantly reduced.
In Japan, the process developed under the COURSE 50 research project (“CO2 Ultimate Reduction in Steelmaking Process by Innovative Technology for Cool Earth 50”) enables the introduction of hydrogen-enriched COG into the blast furnace to reduce carbon emissions.
This research project also aims to separate and recover CO2 from the BFG. The Korean consortium POSCO/RIST is also developing a conversion process to produce a hydrogen-rich gas from COG and CO2 through steam reforming, which could be used for iron ore reduction in a blast furnace or SR process.
Fuel cell technology in buildings
The co-generation of power and heat allows the waste heat that occurs during power generation to be used for heating purposes. This can significantly increase overall energy efficiency in the buildings sector. Decentralised generation of electricity and heat using micro co-generation systems enables this benefit to be realised in the absence of district heating networks.
Many different natural gas-powered co-generation systems using ICEs are already available on the market. Fuel cell micro co-generation systems powered by natural gas are an alternative to conventional ICE systems.
Currently, the electrical efficiency of fuel cell micro co-generation systems is around 42%, being around 10 percentage points higher than for ICE micro co-generation systems.
The downside is significantly higher investment cost: while ICE-based systems cost around USD 2 200 per kW, commercially available fuel cell systems typically cost more than USD 9 000 per kW for commercial applications and more than USD 18 000 per kW for home systems.
Fuel cell micro co-generation systems are either based on a PEMFC or a solid oxide fuel cell (SOFC), the latter providing much higher temperature heat.
Although systems with up to 50 kW electrical output exist, most commercially available systems have electrical power outputs of around 1 kW, therefore being insufficient to fully supply the average US or European dwelling.
However, in the Japanese market more than 120 000 Ene-Farm fuel cell micro co-generation systems of that power category have already been sold under a government subsidy that lasted until September 2014.
All natural gas-based micro co-generation systems need a high difference between local natural gas and electricity prices, the so-called “spark-spread”.
Together with higher efficiency, annual availability and government incentives, the spark-spread forms the economic basis for selecting a micro co-generation system over grid electricity and conventional domestic hot water boilers for heating and hot water supply.
The Japanese Ene-Farm experience
In 2009, a consortium of major Japanese energy suppliers and fuel cell manufacturers began marketing co-branded fuel cell micro co-generation units with an electrical output of between 700 W and 1 000 W to Japanese customers.
The Ene-Farm system can be ordered with two different fuel cell types, using PEMFC and SOFC technologies, with PEMFC systems making up 90% of cumulative sales.
With power output up to 1 kW, the system is not intended to cover the entire electricity demand of an apartment or family house, but to significantly contribute to the electricity demand and to fully cover the hot water demand. Since their introduction, approximately 120 000 units have been installed in Japanese buildings (Figure 8).
Initially a subsidy of almost USD 15 000 per unit was granted by the Japanese government, dropping to below USD 4 000 by 2014. Overall, the unit price had fallen from around USD 45 000 in 2009 to around USD 19 000 by 2014.
This means that a learning rate of more than 15% (i.e. reduction in price per doubling of installed units) has been achieved during the large-scale demonstration phase.* The Ene-Farm system demonstrates that similar learning rates assumed for PEMFC units in the car-manufacturing sector are feasible at larger annual production volumes.
Nonetheless, to reach the target of several hundred thousand installed units in the near future, and millions of units by 2030 (as suggested by the Ene-Farm consortium), costs need to decline even further.
So far, around 30% of the cost of the PEMFC unit is accounted for by the water tank (which is necessary for conventional boilers as well) and only 15% by the fuel-cell stack. The BOP (25%), the fuel-processing unit (15%) and the packaging (15%) account for the remaining 55% of total costs.
This means that further cost reductions will be harder to achieve, as the fuel stack is currently a relatively small share of the overall cost of the unit.
In Japan, equipping 10% of households (i.e. 5.3 million) with fuel-cell co-generation systems is estimated to cut total residential energy demand by 3%, resulting in 4% emission reductions compared to the use of gas boilers and grid electricity for residential energy supply.
Ene-Farm products are also intended to be sold on the European market, where differences in gas quality and much higher presence of potentially poisonous constituents in the European gas require the re-engineering of the gas processing unit for PEM systems.
Other niche applications based on fuel cell technologies
Several other hydrogen-based niche applications exist that are currently applied across different sectors. These applications comprise fuel cell powered fork lifts, autonomous power systems for either stationary or portable off-grid applications, and uninterruptible power systems for back-up power.
Since 2009, over 8 200 fuel cell materials handling equipment units have been deployed in the United States.
Benefiting from longer lifetimes and shorter and less-frequent refuelling cycles, fuel cell forklifts have demonstrated acceptable payback periods and improved cost-effectiveness compared to battery-powered forklift applications used in indoor warehouse operations.
Stationary fuel cell systems in the range of several kilowatts to multiple megawatts are used for remote power and back-up power applications. They are used to supply for example telecommunication towers, networking equipment or datacentres with resilient and reliable power.
In these cases, fuel cell systems often replace diesel generators, providing longer lifetimes as well as less maintenance. The entire range of fuel cell types is represented within this market.
While smaller systems in the range up to several kilowatts of output electricity are most often based on PEMFCs, bigger systems up to the multi-megawatt range mostly build on high-temperature fuel cells such as molten carbonate (MC) or solid oxide (SO) fuel cells.
Many of the fuel cell systems rely on natural gas or hydrogen as primary fuel, but other liquid fuels such as methanol, ethanol, liquefied petroleum gas (LPG) and diesel or kerosene as well as gaseous fuels such as biogas, propane, butane and coal syngas are being used as well. In 2013, stationary fuel cell systems accounted for almost 90% of the shipped systems.
Key hydrogen generation technologies
The following sections briefly discuss selected hydrogen generation technologies, such as reformers and electrolysers. The Technical Annex to this roadmap provides more detailed information on specific technical issues.
Steam methane reforming
Around 48% of hydrogen is currently produced from natural gas using the SMR process, which is based on a reaction of methane and water steam at high temperatures in the presence of a catalyst.
As CO2 concentration in the exhaust gas is high, SMR units are promising candidates for the application of CCS technology, potentially leading to an 80% reduction in its carbon emissions.
Produced on a large scale, hydrogen costs mainly depend on the natural gas price, and are currently between USD 0.9 per kg in the United States, USD 2.2 per kg in Europe and USD 3.2 per kg in Japan.
Very small-scale reforming units exist with production rates down to 4.5 kg of hydrogen per hour, but generation costs are much higher and in the same order of magnitude as hydrogen produced via electrolysis (Table 9).
Reforming processes are not limited to the use of natural gas. All hydrogen-rich gases can be used to produce pure hydrogen via adapted reforming processes.
Following gasification as a first step, hydrogen can be produced from other fossil resources such as coal and also from biomass or organic waste materials.
Electrolysis is a process of splitting water into hydrogen and oxygen by applying a direct current, converting electricity into chemical energy. Currently, around 8 GW of electrolysis capacity are installed worldwide.
For electrolysers using only electric power (and no external heat) as input energy, the efficiency of hydrogen production decreases with cell voltage while the hydrogen production rate increases with cell voltage.
At a given cell geometry, the operator therefore has to deal with a trade-off between electrolyser efficiency and hydrogen output.
Different types of electrolysers are distinguished by their electrolyte and the charge carrier, and can be grouped into: 1) alkaline electrolysers; 2) PEM electrolysers; and 3) SO electrolysers.
All electrolysers consist out of the electrolyser stack, comprising up to 100 cells, and the BOP. Stacks can be mounted in parallel using the same BOP infrastructure, which is why electrolysers are highly modular systems.
While this makes the technology very flexible with respect to hydrogen production capacity, it also limits the effects of economies of scale, as even large electrolysers are based on identically sized cells and stacks.
Alkaline electrolysers are currently the most mature technology, and investment costs are significantly lower than for other electrolyser types.
Although alkaline electrolysers currently have higher efficiencies than electrolysers using solid electrolytes, PEM and SO electrolysers have much higher potential for future cost reduction and, in case of SO electrolysers, efficiency improvements (Figure 9).
PEM electrolysers are particularly interesting as they show both the highest current density and operational range, prerequisites necessary to reduce investment costs and improve operational flexibility at the same time.
As of today, cell lifetime is a limiting factor for PEM and SO electrolyser technologies. The cost of electrolytic hydrogen is largely determined by the cost of electricity and the investment costs associated with the electrolyser.
Minimising the costs of input electricity is likely to be accompanied by lower annual utilisation rates, as very low-cost, surplus renewable electricity will only be available for a limited amount of time per year, which further stresses the impact of investment costs.
It is therefore important to find the right balance between reducing investment costs and achieving efficiency improvements.
Key hydrogen conversion and storage technologies
The following section briefly discusses selected hydrogen conversion and storage technologies. The Technical Annex to this roadmap provides more detailed information on specific technical issues.
Fuel cells allow the oxidation of hydrogen-rich fuel and its conversion to useful energy without burning it in an open flame.
Compared to other single-stage processes to convert chemical energy into electricity, e.g. open-cycle gas turbines, their electrical efficiency is higher and in the range of 32% to up to 70% (HHV).
Fuel cells operate with a variety of input fuels, not only hydrogen. These include natural gas and also liquid fuels such as methanol or diesel. If pure hydrogen is used, the exhaust of fuel cells is water vapour and so has very low local environmental impact.
However, if hydrocarbon fuels are used, using fuel cells for power generation produces CO2 emissions, and so can only confer a climate benefit by operating at higher efficiency than alternative combustion methods.
Nevertheless, experience with fuel cells based on hydrocarbons has a high value for low-carbon innovation due to the applicability of technological advances to fuel cells more generally.
This is partly because hydrocarbon fuels are often reformed to hydrogen in a step that precedes the fuel cell and also because some hydrocarbons may be produced by lower carbon processes in future, e.g. methanol.
Similar to electrolysers, fuel cells are subject to a trade-off between efficiency and power output. Efficiency is highest at low loads and decreases with increasing power output.
In comparison to conventional technologies, fuel cells can achieve their highest efficiencies under transient cycles, such as in passenger cars. As in the case of electrolysers, different fuel cell types exist, which can mainly be distinguished by their membrane type and operating temperature.
Fuel cells can be categorised into: 1) PEMFC; 2) alkaline fuel cell; 3) phosphoric acid fuel cell (PAFC); 4) molten carbonate fuel cell (MCFC); and 5) SOFC.
While PEMFCs and alkaline fuel cells have low operating temperatures of around 80°C, the others operate at higher temperatures of up to 600°C (SOFC), which makes them more suitable to combined heat and power applications.
The higher the temperature, the better the efficiency at otherwise similar parameters. PEMFCs are the most suitable option for FCEVs.
According to the US Department of Energy (DOE) 2013 Fuel Cell Technologies Market Report, the global market for fuel cells grew by almost 400% between 2008 and 2013, with more than 170 MW of fuel cell capacity added in 2013 alone (Figure 10).
Currently, more than 80% of fuel cells are used in stationary applications, such as co-generation, back-up and remote power systems. While the
United States ranks first for fuel cell power capacity, Japan ranks first for delivered systems due to the successful upscaling of the Ene-Farm micro co-generation power system.
Although fuel cells saw remarkable development over the last decade, high investment costs and relatively limited lifetimes remain the greatest barriers to their wider application.
Investment costs greatly depend on manufacturing cost, and could be significantly reduced with economies of scales.
According to the US DOE, PEMFC systems for FCEVs show the highest cost reduction potential at high production volumes, and are targeted to ultimately reach costs of around USD 30 per kW (Figure 11), which would be equivalent to ICE engines.
Investment costs for stationary fuel cell systems are predicted to drop much more slowly, primarily due to the focus on higher efficiencies and longer life times.
The target cost set by the US DOE for the 2020 time frame amounts to between USD 1 500 per kW and USD 2 000 per kW for medium-sized fuel cell co-generation systems.
Hydrogen gas turbines
While gas turbines adapted to burn gases with high hydrogen content (up to 45%) are commercially available, the same cannot be said for gas turbines capable of burning pure hydrogen.
While technological modifications would be moderate, there is currently little demand for such equipment.
In the future, gas turbines able to burn very high shares of hydrogen will be needed for power generation based on the use of fossil fuels and pre-combustion CCS, e.g. in integrated gasification combined cycle (IGCC) power plants with CCS.
This application is currently driving RD&D efforts in gas turbines able to burn gases with very high hydrogen content.
Gas turbines able to react rapidly to changes in gas quality, especially with respect to hydrogen content, are necessary if blending hydrogen in the natural gas grid (power-to-gas) is to become a means of integrating otherwise-curtailed renewable power into the power sector.
Compressors are a key technology for hydrogen storage. Hydrogen pressure levels range from 2 MPa to 18 MPa for underground storage, over 35 MPa to 50 MPa for gaseous truck transport and up to 70 MPa for on-board storage in FCEVs.
A recent study from the US National Renewable Energy Laboratory (NREL) concluded that very sparse data are available on compression technology at very high pressures (e.g. needed for FCEV on-board storage), with energy demand necessary for compression varying by a factor of ten among technologies.
This is largely due to the fact that to date such high pressure compressors are produced in small numbers, as only very little demand exists.
Hydrogen storage in tanks and solid structures
Mature options for storage of hydrogen in vessels comprise pressurised and cryogenic tanks, providing hydrogen storage capacities of between 100 kilowatt hours (kWh) (pressurised tanks) and 100 GWh (cryogenic storage).
While pressurised tanks have high costs due to their limited energy density, cryogenic tanks provide limited storage time due to the boil-off stream losses, necessary to maintain acceptable pressure levels.
An intermediary solution between pressurised and cryogenic hydrogen storage is cryo-compressed hydrogen.
In this case, liquefied hydrogen is filled to the tank, but the pressures levels until hydrogen needs to be flared are much higher (up to 35 MPa) compared to cryogenic storage (around 2 to 4 MPa).
This allows cryo-compressed hydrogen to be stored for longer time periods. Storing hydrogen in metal hydrides or carbon nano-structures are promising technology options for achieving high volumetric densities.
While metal hydrides are already in the demonstration phase, fundamental research is still needed to better understand the potential of carbon nano-structures.